Well control is an important aspect of oil and gas exploration. When drilling a well in, for example, oil and gas exploration applications, devices must be put in place to prevent injury to personnel and equipment associated with drilling activities. One such well control device is known as a blowout preventer (BOP).
BOPs are generally used to seal a wellbore. For example, drilling wells in oil or gas exploration involves penetrating a variety of subsurface geologic structures, or “layers.” Generally, each layer is of a specific geologic composition such as, for example, shale, sandstone, limestone, etc. Each layer may contain trapped fluids or gas at different formation pressures, and the formation pressures generally increase with increasing depth. The pressure in the wellbore is typically adjusted to at least balance the formation pressure by, for example, increasing the density of drilling mud in the wellbore or increasing the pump pressure at the surface of the well.
There are occasions during drilling operations when a wellbore may penetrate a layer having a formation pressure that is substantially higher than the pressure maintained in the wellbore. When this occurs, the well is said to have “taken a kick.” The pressure increase associated with this “kick” is generally produced by an influx of formation fluids (which may be a liquid, a gas, or a combination of liquid and gas) into the wellbore. The relatively high pressure “kick” tends to propagate from a point of entry in the wellbore uphole (from a high pressure region to a low pressure region). If the “kick” is allowed to reach the surface, drilling fluid, well tools, and other drilling structures may be blown out of the wellbore. These blowouts often result in catastrophic destruction of the drilling equipment (including, for example, the drilling rig) and a substantial risk of injury or death to rig personnel.
Because of the risks associated with blowouts, BOPs are typically installed at the surface or on the sea floor in deep water drilling arrangements so that “kicks” may be adequately controlled and circulated out of the system. BOPs may be activated to effectively seal a wellbore until active measures can be taken to control the kick.
Because of the extreme pressure that can be released during a kick, it is common practice to operate a “stack” of BOPs, where several BOPs are connected in a vertical relationship. For example, FIG. 1 shows a BOP stack 100 with an upper BOP 104 stacked on top of a lower BOP 102. Typically, the bottom end of the lower BOP 102 is coupled to the well head (not shown), and the top end of the upper BOP 104 is coupled to drilling or production equipment (not shown). It is also common to include more than two BOPs in an BOP stack.
Each BOP 102, 104 typically includes a center passage (shown in dashed lines) that passes vertically through the BOPs 102, 104. It is these passages that well tools pass through during drilling and that the crude oil and gas passes through during production. It will be understood that each BOP 102, 104 may include rams, blocks, bonnets, and other BOP equipment that are not shown in FIG. 1. FIG. 1 is intended only to show the relative positions of BOPs in a BOP stack.
The BOPs 102, 104 are coupled together at the upper end of the lower BOP 102 and the lower end of the upper BOP 104. FIGS. 2A–2C show several prior art methods for coupling two BOPs together.
FIG. 2A shows a side view of a BOP stack 200 with a lower BOP 202 and an upper BOP 204 that are coupled together. The BOPs 202, 204 are coupled in a “flange-to-flange” arrangement. The lower BOP 202 has an upper flange 203, and the upper BOP 204 has a lower flange 205. The flanges 203, 205 are mated against each other so that the internal bores (shown in dashed lines) of each BOP 202, 204 are lined up.
Studs 207 are passed through both the flange 203 on the lower BOP 202 and the flange 205 on the upper BOP 204. A nut 209 is used on each end of each stud 207 to retain the flanges 203, 205 in place and couple the BOPs 202, 204 together. FIG. 2A shows only two studs 207, but a typical BOP stack may use twelve studs arranged in a bolt pattern around the flanges 203, 205. A larger BOP will generally require more studs, and there is no limit to the number used.
FIG. 2B shows a cross section of a BOP stack 210 in a “flange-to-stud” arrangement. The upper BOP 214 includes a lower flange 215 that is mated against a sealing surface 216 on the top of the lower BOP 212. The lower BOP 212 does not include a flange. Studs 217 are fixed in the lower BOP 212 about the center passage (shown in dashed lines), and the studs 217 pass through the flange 215 of the upper BOP 214. Nuts 219 retain the flange 215 on the upper BOP 214 against the sealing surface 216 on the lower BOP 212.
FIG. 2C shows a cross section of a BOP stack 220 that includes two BOPs 222, 224 connected using a “stud-to-stud” arrangement with a spool 231. The spool 231 includes an upper flange 232, a lower flange 233, and a central passage (shown in dashed lines) that is aligned with the central passages of the BOPs 222, 224. Each of the BOPs 222, 224 includes studs 227 that are fixed about the central passage. The spool is aligned with the studs 227 on each BOP 222, 224, and the studs pass through the flanges 232, 233 of the spool 231. Nuts 229 retain the spool in place to connect the BOPs 222, 224.
Each of these connection methods requires the use of at least one flange, which adds to the height of the BOP stack. Because of the limited space near the well head, it is desirable to reduce the BOP stack height as much as possible.